Typical fracturing systems move a fracture sleeve to uncover ports in a completion string. In a conventional fracture system, this is achieved by landing a dropped ball on a ball seat attached to the sleeve. Once a sufficient pressure differential is achieved across the ball, the seat and the attached fracturing sleeve are moved axially to uncover the ports. Fracturing fluid ibs pumped downhole and out into the surrounding formation through the ports. In order to fracture a multi-zone well, the ball seats decrease in diameter from the heel to the toe of the well. The smallest ball is dropped first and passes through all the larger ball seats until it lands on the seat closest to the toe of the well. Once the first zone has been successfully fractured, successively larger balls can then be dropped to initiate fracture port opening for each subsequent fracture zone.
The ever decreasing ball seats have several known disadvantages. The restrictions in inner diameter through the ball seats have a negative impact on the effectiveness of the fracture closest to the toe of the well. This disadvantage can be overcome by the use of powerful pumps to transmit fracturing fluid through the narrow bore, although this is costly.
Additionally, once fracturing operations are complete, the balls must be removed from the system before production can begin. Existing methods for removing the balls involve drilling out the balls and seats, flowing the balls back to surface and/or using dissolvable balls. Each of these methods is time consuming and pose a risk and/or limitation to production of hydrocarbons.
The present invention aims to alleviate at least some of the aforementioned disadvantages.
It is an object of at least one aspect of at least one embodiment of the present invention to seek to obviate or at least mitigate one or more problems and/or disadvantages in the prior art.
According to a first aspect of the present invention there is provided a method of fracturing a formation surrounding a well bore comprising the steps of:                (i) providing a tubular including at least two portions, each portion comprising an annulus isolation means, a selective flow path between the interior and the exterior of the tubular and a throughbore isolation means;        (ii) running the tubular into the wellbore;        (iii) isolating an annulus between the exterior of the tubular and the wellbore to thereby create at least two isolated zones;        (iv) electing any zone to be fractured;        (v) remotely opening the flow path in the portion of tubular corresponding to the selected zone;        (vi) remotely isolating the throughbore of the tubular by closing the throughbore isolation means in the portion of tubular corresponding to the selected zone; and        (vii) fracturing at least part of the formation surrounding the well. The method can also include the steps of:        (viii) remotely closing the flow path in the portion of tubular corresponding to the selected zone; and        (ix) opening the throughbore of the tubular by remotely opening the throughbore isolation means in the portion of tubular corresponding to the selected zone.        
At least steps (iv)-(vi) can be repeated to thereby fracture at least part of the formation surrounding a different zone of the well.
Step (iv) can include the step of selecting an uphole zone to be fractured before a downhole zone to be fractured.
In this context, “uphole” can be construed as meaning closer to either a heel of the wellbore or the surface and “downhole” can be taken to mean closest to a toe of the well distal from the surface.
The throughbore is preferably isolated downhole of the flow path. Preferably the throughbore isolation means in each portion of tubular is located immediately downhole of the selective flow path. The throughbore isolation means is preferably positioned proximate the selective flow path in each portion of the tubular.
The method can further include the steps of:
providing a tubular including a plurality of portions;
creating a plurality of zones;
selecting one zone at a time in any order; and
successively fracturing at least a portion of the formation surrounding each selected zone.
The method can include:
providing a tubular including a plurality of portions;
creating a plurality of zones;
selecting one zone at a time in a sequential manner; and
sequentially fracturing at least a part of the formation surrounding each selected zone.
The method can include:
selecting one zone at a time in a sequential manner from a heel of the well towards a toe of the well, and
sequentially fracturing at least a part of the formation surrounding each selected zone.
In a deviated well, the heel of the well typically refers to the part of the well closest to the point of deviation. The toe of the well typically refers to the part of the well distal from the deviated portion.
Alternatively, the method can include:
selecting one zone at a time in a sequential manner from a toe of the well towards a heel of the well; and
sequentially fracturing at least a portion of the formation surrounding each selected zone.
The method of the invention has the advantage that it allows fracturing of a formation surrounding a wellbore to occur in any sequence, e.g. zones created can be fractured in any order. This allows fracturing of the well to occur sequentially from the heel to the toe of the well or from the toe to the heel of the well. Alternatively, fracturing of the zones can occur out of sequence and in any order.
The method of the invention allows the fracturing operation to be performed remotely. Thus all tools can be actuated and controlled from surface with no mechanical intervention required. “Remotely” in the context of the invention can mean controlling operations from the surface of the well without direct mechanical intervention downhole.
Remote downhole actuation can be achieved by any method selected from the group including communicating actuation commands to the downhole tool using: pressure modulations (detector in tool), nuclear source (detector in tool), chemical source (tracer in tool), radio source (reader in tool), acoustic source (hydrophone in tool), and magnetic source (reader in tool).
These examples of methods, by which the tools making up the tubular can be remotely actuated, require some detector within the downhole tool. The detector (or equivalent) within the tool can be electrically connected to a circuit capable of recognising the unique signal, processing that information and an actuation command and initiating actuation of the tool. One example of such a detector and electronic circuit embedded within a downhole tool is disclosed in published patent GB 2 434 820 B.
The method can include remotely actuating the selective flow path by communicating an actuation command downhole using at least one of the following remote actuation means selected from the group consisting of: radio frequency source; pressure sequencing; and timed actuation.
The selective fluid flow path between the interior and the exterior of the tubular can be provided by a downhole tool such as a sleeve valve that is movable to selectively open and close ports extending through a sidewall of the tubular to selectively create and obturate a flow path respectively.
The method can include remotely isolating the throughbore of the tubular by communicating an actuation command to the throughbore isolation means using at least one of the following remote actuation means selected from the group consisting of: radio frequency source, pressure sequencing and timed actuation.
The throughbore isolation means can be an isolation valve that selectively seals the throughbore. The throughbore isolation valve can be a flapper valve pivotable between a stowed position in which the throughbore is unobstructed and a deployed position in which the flapper substantially obturates the throughbore.
The method can include remotely actuating tools downhole by circulating objects downhole said objects being communicable with the tools when the tubular represents an open system such that fluids are flowable within the throughbore.
The tubular represents an open system when the tubular has at least one opening such that fluids sent downhole flow within the throughbore.
Objects that may be circulated downhole, said objects being communicable with the tools include: nuclear source, chemical source, radio source or magnetic source. Objects can be communicated downhole by gravity, pumping, adding them to fluid flow or any combination thereof.
One object circulated downhole can be a radio frequency identification tag. The downhole tools can be provided with readers (such as an antenna) coupled to an
electronic circuit within the tool for detecting the presence of a radio frequency identification tag. Such a system is described in patent GB 2 434 820 B.
The method can include remotely determining actuation from surface by actuating the tools downhole using signals from surface or providing tools with pre-programmed timers to actuate the tools when the tubular represents a closed system.
The tubular represents a closed system when there are no openings within the tubular, such that fluids cannot flow freely within the tubular but instead back up within the throughbore.
The signals from surface for remote actuation of the tools can include pressure or acoustic signals. The signals from surface can include pressure sequencing.
Remote actuation by pressure sequencing can include modulated pressure sequencing. A distinctive profile of pressure modulations can be created at surface by modifying the pressure in the tubing. Transducers embedded within downhole tools can be pre-programmed such that the downhole tool is actuable in response to a distinctive pressure modulation profile.
The method can be a method of fracturing and producing hydrocarbons from a formation surrounding a wellbore including the steps of producing from the selected zones following the fracturing steps.
Hydrocarbons can be produced through the selective flow path. Alternatively, each portion of tubular can include a production flow path between the interior and the exterior of the tubular. The production flow path can be selectively actuable by movement of a sleeve valve to selectively cover ports extending through the sidewall of the tubing. The production ports can be provided with a mesh to restrict entry of particles above a predetermined size. The mesh can be a sand screen.
The method can include reselling to a primary configuration at the end of each fracturing operation, in which primary configuration the selective flow path(s) are closed and the throughbore isolation means are open such that the throughbore is unobturated.
The apparatus can be run into the wellbore in the primary configuration.
The method can include the step of automatically returning to the primary configuration after a predetermined period of time.
Downhole tools can be pre-programmed to a default configuration. The default configuration can be the primary configuration. All downhole tools can return to the default configuration after a certain or predetermined period of time, e.g. 6 hours, 12 hours, 24 hours or 48 hours. At least some downhole tools can be provided with a timer connected to the electronic circuit to return the downhole tool to the default configuration.
The method can include remotely actuating the tools to adopt a default configuration.
The method can also include providing all tools with a timer pre-programmed to remotely actuate the tools in their default configurations.
In the default configuration the throughbore isolation means can be open and the fluid flow paths can be closed.
Step (vii) can include pumping fracturing fluid through the tubular and directing fracturing fluid through the fluid flow path to fracture at least part of the surrounding formation. Step (vii) can include diverting fluid through the fluid flow path using the throughbore isolation means as a diverter.
Step (vii) can include fracturing at least part of the formation surrounding the well by pumping a fracturing fluid into the formation. The method can include different fracturing methods such as hydraulic fracturing or acid fracturing.
Step (vii) can include pumping fracturing fluid having particles suspended therein into the formation.
Suitable fluids having particulates suspended therein can be referred to as proppant fracturing fluids. Step (vii) can include pumping proppant fracturing fluid into the formation so that the method of the invention is a method of proppant fracturing a formation. The proppant fracturing fluid can include a mixture or gel of water, proppant and thickening agent in concentrations adjusted for the specific application. The proppant can include sand or ceramic beads. The thickening medium can include xanthum gel.
The method can include pumping fracturing fluid having particles suspended therein until the fractured part of the formation is full of particles and pumped fracturing fluid backs up within the throughbore of the tubular.
The method can include clearing particles within the throughbore by opening another selective flow path in a different zone, and pumping fluids within the throughbore, which fluids urge the particles into a different zone.
At least one clean-up (non-production) zone with an associated selective flow path and isolation means can be created for accepting particles to be cleared. A clean-up zone can be created at the end of the well closest to the toe.
This method maximises proppant packing in a zone by fracturing the formation until the fractured formation is full of proppant (a situation know as ‘sand out’).
Annulus isolation means can typically be provided on either side of the selective flow path in each portion of tubular. Isolating the annulus can be achieved by actuating annulus isolation means. The annulus isolation means can be a packer.
The method can include remotely actuating an annulus isolation means to isolate the annulus.
The method can include actuating the annulus isolation means by communicating actuation commands to the tool using a method selected from the group consisting of: radio frequency source; flow activation; timed activation; chemical actuation; and pressure signature actuation.
As an alternative, the annular isolation means can be mechanically actuated.
The method steps (i)-(ix) can be chronological. However, it will be appreciated that the method steps may not be necessarily chronological. For example, isolating the annulus to create zones can be achieved by flow actuable packers that are arranged to actuate by flowing fracturing fluid over the packer; thus step (iii) may occur simultaneously with step (vii).
The method can include anchoring the tubular in the wellbore prior to commencement of the fracturing operation. The method can include anchoring the tubular in the wellbore between method steps (ii) and (iii). The method can include anchoring the tubular in the wellbore towards an upper end of the tubular. The method can include anchoring the tubular in the wellbore in at least one other location along the length of the tubular. The method can include anchoring the tubular in the wellbore towards a toe end of the well.